U.S. patent number 10,508,511 [Application Number 15/553,888] was granted by the patent office on 2019-12-17 for rotary actuator for actuating mechanically operated inflow control devices.
This patent grant is currently assigned to Halliburton Energy Services, Inc.. The grantee listed for this patent is Halliburton Energy Services, Inc.. Invention is credited to Jimmie R. Williamson.
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United States Patent |
10,508,511 |
Williamson |
December 17, 2019 |
Rotary actuator for actuating mechanically operated inflow control
devices
Abstract
A rotary actuator operates an inflow control device in a tubing
string. The rotary actuator includes a stationary member, a drive
member, and a locator device, where the locator device anchors the
rotary actuator at a predetermined location in a tubing string. The
drive member rotates relative to the stationary member, and
operates the inflow control device. A method of actuating an inflow
control device with a rotary actuator, the method comprising:
conveying the rotary actuator to a predetermined location in the
tubing string, engaging the engagement members with a profile,
thereby preventing further movement of the rotary actuator into the
tubing string, and rotating the drive member relative to the
stationary member, thereby actuating the inflow control device.
Inventors: |
Williamson; Jimmie R.
(Carrollton, TX) |
Applicant: |
Name |
City |
State |
Country |
Type |
Halliburton Energy Services, Inc. |
Houston |
TX |
US |
|
|
Assignee: |
Halliburton Energy Services,
Inc. (Houston, TX)
|
Family
ID: |
57126907 |
Appl.
No.: |
15/553,888 |
Filed: |
April 17, 2015 |
PCT
Filed: |
April 17, 2015 |
PCT No.: |
PCT/US2015/026515 |
371(c)(1),(2),(4) Date: |
August 25, 2017 |
PCT
Pub. No.: |
WO2016/167811 |
PCT
Pub. Date: |
October 20, 2016 |
Prior Publication Data
|
|
|
|
Document
Identifier |
Publication Date |
|
US 20180038202 A1 |
Feb 8, 2018 |
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B
34/14 (20130101); E21B 47/09 (20130101); E21B
34/12 (20130101); E21B 49/08 (20130101); E21B
47/10 (20130101); E21B 43/14 (20130101); E21B
2200/06 (20200501) |
Current International
Class: |
E21B
34/12 (20060101); E21B 47/10 (20120101); E21B
47/09 (20120101); E21B 49/08 (20060101); E21B
43/14 (20060101); E21B 34/00 (20060101) |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
Other References
International Search Report and Written Opinion dated Jan. 15,
2016; International PCT Application No. PCT/US2015/026515. cited by
applicant.
|
Primary Examiner: Butcher; Caroline N
Attorney, Agent or Firm: McGuireWoods LLP
Claims
What is claimed is:
1. A rotary actuator that adjusts an inflow control device in a
tubing string, the rotary actuator comprising: a stationary member;
a drive member, wherein the drive member rotates relative to the
stationary member, and the drive member adjusts the inflow control
device in response to the rotation of the drive member; a locator
device that anchors the rotary actuator at a predetermined location
in the tubing string; an intermediate sleeve; and an inner sleeve,
wherein the inner sleeve is positioned radially inward from the
stationary member, and the intermediate sleeve is positioned
radially between the stationary member and the inner sleeve,
wherein a first magnetic device in the stationary member is
magnetically coupled to a second magnetic device in the inner
sleeve.
2. The actuator according to claim 1, wherein the stationary member
engages a first recess, wherein the engagement with the first
recess substantially prevents relative rotation between the
stationary member and the tubing string, wherein the drive member
engages a second recess, and wherein the second recess rotates with
the drive member when the drive member is rotated relative to the
tubing string.
3. The actuator according to claim 2, wherein the first recess is
in an inner wall of at least one of the inflow control device and
the tubing string, and wherein the second recess is in an inner
wall of a closure member of the inflow control device.
4. The actuator according to claim 3, wherein the rotation of the
drive member rotates the closure member and wherein the inflow
control device is selectively operated between closed, open, and
partially open positions in response to the rotation of the closure
member.
5. The actuator according to claim 1, wherein the rotary actuator
further comprises a motor, and wherein the motor rotates the drive
member relative to the stationary member.
6. The actuator according to claim 1, wherein the locator device
includes a threaded sleeve and engagement members, and wherein
rotation of the threaded sleeve selectively extends and retracts
the engagement members.
7. The actuator according to claim 1, wherein the locator device
further comprises engagement members that engage a locator profile
in an inner wall of at least one of the inflow control device and
the tubing string when the engagement members are extended, and
wherein the engagement between the engagement members and the
locator profile anchors the rotary actuator at the predetermined
location.
8. The actuator according to claim 1, wherein the magnetic coupling
prevents relative rotation between the stationary member and the
inner sleeve, and wherein the intermediate sleeve rotates relative
to the inner sleeve when the drive member rotates.
9. The actuator according to claim 1, wherein the rotary actuator
further comprises at least one sensor that detects an identifier of
the inflow control device and transmits the detected identifier to
a controller, wherein the controller compares the detected
identifier to an expected identifier and validates that the rotary
actuator is at the predetermined location when the detected
identifier matches the expected identifier.
10. The actuator according to claim 1, wherein a longitudinal flow
passage extends through the tubing string, and wherein the rotary
actuator further comprises at least one sensor that detects at
least one characteristic of a fluid that flows through the
longitudinal flow passage.
11. The actuator according to claim 10, wherein the rotary actuator
operates the inflow control device in response to the detected
fluid characteristic.
12. The actuator according to claim 1, wherein the rotary actuator
further comprises at least one sensor that detects the azimuthal
orientation of the stationary member.
13. A method of adjusting an inflow control device in a tubing
string with a rotary actuator, the method comprising: conveying the
rotary actuator to a predetermined location in the tubing string,
wherein the rotary actuator comprises: (A) a stationary member; (B)
a drive member; (C) a locator device with engagement members; and
(D) an inner sleeve, wherein the inner sleeve is positioned
radially inward from the stationary member, wherein a first
magnetic device in the stationary member is magnetically coupled to
a second magnetic device in the inner sleeve; engaging the
engagement members with a profile in at least one of the inflow
control device and the tubing string, wherein the engagement
prevents further longitudinal movement of the rotary actuator into
the tubing string; engaging the stationary member with a first
recess in at least one of the inflow control device and the tubing
string, and preventing relative rotation between the stationary
member and the tubing string when the stationary member abuts a
wall of the first recess; and rotating the drive member relative to
the stationary member, thereby adjusting the inflow control
device.
14. The method according to claim 13, wherein the step of conveying
further comprises conveying the rotary actuator near a
predetermined location in the tubing string, radially outwardly
extending the engagement members, and then moving the rotary
actuator to the predetermined location.
15. The method according to claim 13, the method further comprising
engaging the drive member with a second recess in a closure member
of the inflow control device, thereby rotating the closure member
when the drive member rotates relative to the tubing string.
16. The method according to claim 15, wherein the step of rotating
the closure member further comprises selectively operating the
inflow control device between closed, open, and partially open
positions in response to the rotation of the closure member.
17. The method according to claim 13, wherein the rotary actuator
further comprises at least one sensor, and wherein the method
further comprises: detecting an identifier of the inflow control
device with the sensor; and transmitting the detected identifier to
a controller, wherein the controller compares the detected
identifier to an expected identifier and validates that the rotary
actuator is at the predetermined location when the detected
identifier matches the expected identifier.
18. The method according to claim 13, wherein the rotary actuator
further comprises at least one sensor, and wherein the method
further comprises: detecting at least one characteristic of a fluid
that flows through a longitudinal flow passage of the tubing
string; and adjusting the inflow control device in response to the
detection.
Description
This is a 371 national stage application of International Patent
Application No. PCT/US2015/026515 filed Apr. 17, 2015, the
disclosure of which is incorporated by reference herein in its
entirety.
TECHNICAL FIELD
A rotary actuator and methods of operating mechanically operated
inflow control devices are provided. The rotary actuator includes
torque keys that are capable of rotating a member of an inflow
control device relative to a tubing string, thereby actuating the
inflow control device. According to certain embodiments, the rotary
actuator is used in an oil or gas well operation.
BRIEF DESCRIPTION OF THE FIGURES
The features and advantages of certain embodiments will be more
readily appreciated when considered in conjunction with the
accompanying figures. The figures are not to be construed as
limiting any of the preferred embodiments.
FIG. 1 depicts a schematic diagram of a well system containing a
rotary actuator that can individually control multiple inflow
control devices of the well system.
FIG. 2 depicts a cross-sectional view of the rotary actuator.
FIGS. 3A-B depict a partial cross-sectional view of an inflow
control device that can be controlled by the rotary actuator.
FIGS. 4A-B depict a cross-sectional view of another inflow control
device that can be controlled by the rotary actuator.
FIGS. 5A-C depict detailed partial cross-sectional views of the
rotary actuator.
FIGS. 6 and 7 depict detailed partial cross-sectional views of a
lower portion of the rotary actuator in various states of
operation.
DETAILED DESCRIPTION
Oil and gas hydrocarbons are naturally occurring in some
subterranean formations. In the oil and gas industry, a
subterranean formation containing oil or gas is referred to as a
reservoir. A reservoir may be located under land or off shore.
Reservoirs are typically located in the range of a few hundred feet
(shallow reservoirs) to a few tens of thousands of feet (ultra-deep
reservoirs). In order to produce oil or gas, a wellbore is drilled
into a reservoir or adjacent to a reservoir. The oil, gas, or water
produced from a reservoir is called a reservoir fluid. As used
herein, a "fluid" is a substance having a continuous phase that
tends to flow and to conform to the outline of its container when
the substance is tested at a temperature of 71.degree. F.
(22.degree. C.) and a pressure of one atmosphere "atm" (0.1
megapascals "MPa"). A fluid can be a liquid or gas.
A well can include, without limitation, an oil, gas, or water
production well, or an injection well. As used herein, a "well"
includes at least one wellbore. A wellbore can include vertical,
inclined, and horizontal portions, and it can be straight, curved,
or branched. As used herein, the term "wellbore" includes any
cased, and any uncased, open-hole portion of the wellbore. The well
can also include multiple wellbores, such as a main wellbore and
lateral wellbores. As used herein, the term "wellbore" also
includes a main wellbore as well as lateral wellbores that branch
off from the main wellbore or from other lateral wellbores. A
near-wellbore region is the subterranean material and rock of the
subterranean formation surrounding the wellbore. As used herein, a
"well" also includes the near-wellbore region. The near-wellbore
region is generally considered to be the region within
approximately 100 feet radially of the wellbore. As used herein,
"into a well" means and includes into any portion of the well,
including into the wellbore or into the near-wellbore region via
the wellbore.
In an open-hole wellbore portion, a tubing string may be placed
into the wellbore. The tubing string allows fluids to be introduced
into or flowed from a remote portion of the wellbore. In a
cased-hole wellbore portion, a casing is placed into the wellbore
that can also contain a tubing string. A wellbore can contain an
annulus. Examples of an annulus include, but are not limited to:
the space between the wellbore and the outside of a tubing string
in an open-hole wellbore; the space between the wellbore and the
outside of a casing in a cased-hole wellbore; and the space between
the inside of a casing and the outside of a tubing string in a
cased-hole wellbore.
As used herein, the relative term "downstream" means at a location
closer to a wellhead, and "upstream" means at a location further
away from the wellhead. As used herein, the phrase "rotationally
fixed" means that one item is substantially prevented from rotating
relative to another item. As used herein, the phrase "substantially
prevented" means that a slight relative rotation from approximately
0 to 10 degrees between the two items can occur while still being
rotationally fixed.
It is not uncommon for a wellbore to extend several hundreds of
feet or several thousands of feet into a subterranean formation.
The subterranean formation can have different zones. A zone is an
interval of rock differentiated from surrounding rocks on the basis
of its fossil content or other features, such as faults or
fractures. For example, one zone can have a higher permeability
compared to another zone. Each zone of the formation can be
isolated within the wellbore via the use of packers or other
similar devices.
It is often desirable to produce a reservoir fluid from multiples
zones of a formation. However, there are problems associated with
producing from or injecting into multiple formation zones. A zone
with higher permeability can produce fluid at a higher rate when
compared to another zone with reduced permeability. Higher flow
rate from one zone may cause accelerated degradation of the
wellbore components related to that zone due to higher fluid
velocities. It may be desirable to reduce flow velocity from the
high permeability zone by increasing flow restrictions to the
inflow of fluid from the zone into the tubing string. Additionally,
it may be desirable to increase flow velocity from the low
permeability zone by decreasing flow restrictions to the inflow of
fluid from the zone into the tubing string. Also, some zones may
produce more water than other zones. In oil and gas wells, it is
desirable to minimize the amount of water being produced with the
oil and/or gas. In injection wells, it is often desirable to
control the injection rate of a fluid (e.g., steam) into each zone
to provide a better distribution of the fluid being injected into
the zones.
Fluid flow from the tubing string into a subterranean formation
(e.g., injection) or fluid flow from the subterranean formation and
into the tubing string (e.g., production) can be regulated by
controlling at least one inflow control device in each zone to
selectively restrict fluid flow between the tubing string and the
subterranean formation. However, each inflow control device
normally requires control lines connected directly to the device
for control of the device. With multiple zones, an increased number
of inflow control devices can be required, thereby increasing the
number of control lines needed. Additional lines can present even
more problems for the well system, by requiring more penetrations
of annular seals (e.g., packers), having an increased potential for
damage, etc. Therefore, there is a need to provide control for the
inflow control devices in a multi-zone well system, without
incurring the problems caused by the additional control lines.
It has been discovered that a rotary actuator can mechanically
adjust the flow rate of fluid flow through the inflow control
devices without the need for control lines connected directly to
the devices. Mechanically actuated inflow control devices do not
necessarily require direct connection to control lines for
actuation, and these inflow control devices can be much less
complicated than hydraulically, electrically, or optically actuated
inflow control devices. As used herein, "mechanically actuated"
refers to a device being actuated by the application of a
mechanical force such as a rotational and/or longitudinal
displacement force that acts on a component of the device and
without electrical energy, optical energy, magnetic coupling, or an
increased fluid pressure being applied to the device.
According to certain embodiments, a rotary actuator that adjusts an
inflow control device in a tubing string is provided, the rotary
actuator including, (A) a stationary member, (B) a drive member,
where the drive member rotates relative to the stationary member,
and the inflow control device is operated in response to the
rotation of the drive member, and (C) a locator device that anchors
the rotary actuator at a predetermined location in a tubing
string.
According to other embodiments, a method of adjusting an inflow
control device in a tubing string with a rotary actuator is
provided. The methods can include the steps of conveying the rotary
actuator to a predetermined location in the tubing string, where
the rotary actuator includes: (A) a stationary member, (B) a drive
member, and (C) a locator device with engagement members. Engaging
the engagement members with a profile in the inflow control device
and/or the tubing string thereby prevents longitudinal movement of
the rotary actuator into the tubing string, and rotating the drive
member relative to the stationary member, thereby actuating the
inflow control device.
Any discussion of the embodiments regarding the rotary actuator or
any component related to the rotary actuator is intended to apply
to all of the apparatus and method embodiments.
Turning to the Figures, FIG. 1 depicts a well system 10. The well
system 10 can include at least one wellbore 11. The subterranean
formation 20 can be a portion of a reservoir or adjacent to a
reservoir. The wellbore 11 can include a casing 15. A tubing string
24 with an internal flow passage 28 can be installed in the
wellbore 11. The subterranean formation 20 can have at least a
first zone 12 and a second zone 13.
The well system 10 can include at least a first wellbore interval
16 and a second wellbore interval 17. The well system 10 can also
include more than two wellbore intervals, for example, the well
system 10 can further include a third wellbore interval 18, a
fourth wellbore interval 19, and so on. At least one wellbore
interval can correspond to a zone of the subterranean formation 20.
By way of example, the first wellbore interval 16 can correspond to
the first zone 12.
The well system 10 can include one or more packers 26. The packers
26 can create the wellbore intervals and isolate each zone of the
subterranean formation 20. The packers 26 can prevent fluid flow
between one or more wellbore intervals (e.g., between the first
wellbore interval 16 and the second wellbore interval 17) via an
annulus 21.
The rotary actuator 40 can travel through the longitudinal flow
passage 28 of the tubing string 24 on a conveyance 32 to each of
the inflow control devices 30 and actuate each device 30 through
mechanical manipulations. As used herein, "conveyance" refers to a
means of transporting the rotary actuator 40 through the tubing
string 24, such as coiled tubing, a wireline, a tractor system, a
segmented tubing string, etc. Multiple inflow control devices 30
can be adjusted (e.g., actuated between open, closed, and partially
open positions) during a single trip of the rotary actuator 40 into
the wellbore 11. An inflow control device 30 can also be used to
control fluid flow through a well screen 36 as indicated in
wellbore interval 17.
It should be noted that the well system 10 illustrated in the
drawings and described herein is merely one example of a wide
variety of well systems in which the principles of this disclosure
can be utilized. It should be clearly understood that the
principles of this disclosure are not limited to any of the details
of the well system 10, or components thereof, depicted in the
drawings or described herein. Furthermore, the well system 10 can
include other components not depicted in the drawing. For example,
the well system 10 can further include a crossover valve assembly.
By way of another example, cement may be used instead of, or in
addition to, the packers 26 to provide zonal isolation.
The rotary actuator 40 can include a locator device 46 that locates
the actuator 40 at a predetermined location within the tubing
string 24. The predetermined location can be the location of a
downhole tool (such as an inflow control device 30) in the tubing
string 24. The rotary actuator 40 can also be positioned at the
predetermined location by introducing the actuator 40 a
predetermined distance into the tubing string, or by introducing
the actuator through the tubing string until a sensor 60 (e.g., a
radio frequency identification (RFID) read/write device 104) of the
actuator 40 senses an identifier (e.g., an RFID device) of the
downhole tool that matches an expected identifier, thereby
verifying that the actuator is at the predetermined location.
When the locator device 46 is utilized, the rotary actuator 40 can
be positioned in the tubing string 24 at the predetermined
location, and can engage the locator device 46 with a profile 52 to
anchor the actuator 40 at the predetermined location. As used
herein "anchor" means that the item being anchored (e.g., the
rotary actuator 40) is prevented from any further longitudinal
movement upstream or further into the tubing string 24. However,
longitudinal movement downstream or up and out of the tubing string
24 can be permitted. The profile 52 can be recesses formed in an
inner wall 31 of the inflow control device 30 (as seen in interval
18) and/or in an inner wall 25 of the tubing string 24 (as seen in
intervals 16, 17, 19).
When the rotary actuator 40 is at the predetermined location, the
rotary actuator 40 uses a stationary member 44 and a drive member
42 to impart rotational movement to a component of the inflow
control device 30, thereby actuating the inflow control device 30
between open, closed, and/or partially open positions. The rotary
actuator 40 can then be moved to another inflow control device 30
in the wellbore (either upstream or downstream) to actuate another
inflow control device 30 between open, closed, and/or partially
open configurations. This process can continue until all inflow
control devices 30 are actuated to their desired configuration.
Referring now to FIGS. 2, 3A-B, and 4A-B, FIG. 2 depicts a more
detailed cross-sectional view of the rotary actuator 40, and FIGS.
3A-B and 4A-B depict two possible inflow control devices 30 that
can be controlled by the rotary actuator 40. The coupling 102 can
be used to couple the rotary actuator 40 to the conveyance 32,
which can be a coiled tubing, a wireline, a tractor system, a
segmented tubing string, etc. When the wellbore 11 is generally
vertical, then a coiled tubing and/or wireline conveyance 32 may be
preferred. However, if the wellbore 11 is generally horizontal or
at least a significant portion is horizontal, then a tractor system
and/or a segmented tubing string conveyance 32 may be
preferred.
The rotary actuator 40 can include a controller 62, a motor 66, at
least one stationary member 44, and at least one drive member 42.
The controller 62 can receive commands from a remote location, such
as the earth's surface, drilling rig, etc., via wired or wireless
telemetry. The controller 62 can interpret and execute the commands
to operate the rotary actuator 40, which in turn can operate an
inflow control device 30. The controller 62 can also receive sensor
data from various sensors 60 (see FIG. 5A), such as temperature,
pressure, fluid viscosity, fluid velocity, tool orientation, RFID
identification, etc. and send this data to the remote location for
processing.
This sensed data can be used to determine whether the rotary
actuator 40 is at the predetermined location or not (e.g., reading
the RFID device), whether the actuator 40 is at a correct azimuthal
orientation (e.g., reading an inclinometer), environmental
conditions at the predetermined location (e.g., reading
temperature, pressure sensors), and what fluids are being produced
or injected at the predetermined location by detecting at least one
characteristic of the fluid at the predetermined location (e.g.,
reading temperature, pressure, fluid viscosity, fluid velocity
sensors). The controller 62 can automatically actuate the inflow
control device 30 at the predetermined location in response to the
sensed data. For example, if the sensor data indicates water is
being produced at the predetermined location, then the controller
62 can actuate the inflow control device 30 to a closed or
partially closed position to prevent or reduce production of water
from the respective wellbore interval (e.g., the first or second
wellbore intervals 16, 17). The controller 62 can also be commanded
from a remote location by an operator at the surface in response to
the sensed data that was sent to the remote location for
processing.
In operation, the rotary actuator 40 can be moved through the
tubing string 24 (not shown in FIGS. 3A-B, 4A-B) to align the
actuator 40 with an inflow control device 30. When positioned in
the tubing string 24 at the predetermined location, a stationary
member 44 can be engaged with a first recess 54 and a drive member
42 can be engaged with a second recess 56. The first recess 54 can
extend radially outwardly from the inner wall 31 of the inflow
control device 30 and is rotationally fixed to an outer housing 38
of the inflow control device 30, where the outer housing is
rotationally fixed to the tubing string 24 (e.g., through threaded
pin and box connections). Therefore, the stationary member 44 is
substantially prevented from rotating relative to the tubing string
24. However, clearances between walls of the first recess 54 and
the stationary member 44 can allow a slight relative rotation
between the stationary member 44 and the first recess 54. When the
stationary member 44 is rotated in a first direction and abuts a
wall of the first recess 54, then any further rotation in the first
direction is prevented. If the stationary member 44 is rotated in a
second direction, which is opposite to the first direction, then
the stationary member 44 can rotate relative to the first recess 54
until the member 44 abuts another wall of the first recess 54,
thereby preventing any further rotation in the second direction.
The relative rotation between the stationary member 44 and the
first recess 54 will generally not exceed 10 degrees before the
stationary member abuts a wall of the first recess 54, thereby
preventing further relative rotation in that direction.
The second recess 56 can be rotationally fixed to a closure member
48 of the inflow control device 30. The second recess 56 can be in
an inner wall 49 of the closure member 48, where the second recess
56 extends radially outwardly from the inner wall 49. Rotation of
the closure member 48 can actuate the inflow control device 30
between open, closed, and partially open positions. When the
controller 62 is commanded to actuate the inflow control device 30,
the controller 62 operates the motor and causes the rotor 69 to
rotate about the axis 130 relative to the stator 68 as indicated by
arrows 132 (FIGS. 3B, 4B). Since the drive member 42 is
rotationally coupled to the rotor 69, the rotor's rotation causes
the drive member 42 to also rotate about the axis 130. Furthermore,
engagement of the drive member 42 with the second recess 56 causes
the second recess 56 to rotate, thereby rotating the closure member
48 and actuating the inflow control device 30.
FIGS. 3A, 4A depict inflow control devices 30 in a fully closed
position with fluid flow being prevented through ports 96. The
rotary actuator 40 is not shown in these figures for clarity. The
closure member 48 of each device 30 can be generally cylindrical in
shape, and can rotate relative to an outer housing 38 of the device
30. The closure member 48 can have any shape so that it can be
rotated to actuate the inflow control device 30. For example, FIG.
3A shows a closure member 48 with a portion that is conically
shaped. When the stationary member 44 and drive member 42 of the
rotary actuator 40 engage the first and second recesses 54, 56,
respectively, the rotary actuator 40 can actuate the inflow control
device 30 to a desired position (e.g., open or partially open) by
rotating the drive member 42 relative to the stationary member 44.
The rotation of the drive member 42 rotates the closure member 48
relative to the outer housing 38, thereby actuating the device 30.
FIGS. 3B, 4B depict inflow control devices 30 in a fully open
position with fluid flow permitted through ports 96 as indicated by
arrows 34.
Please note that the first recess 54 is shown upstream from the
second recess 56 in FIGS. 3A-B, while the first recess 54 is shown
downstream from the second recess 56 in FIGS. 4A-B. Also, the
rotary actuator 40 is shown in FIG. 2 as having the stationary
member 44 and drive member 42 in either the upstream or downstream
positions. If one of the stationary and drive members 44, 42 is
positioned at the downstream position (left in the drawing) then
the other one will be positioned at the upstream position (right in
the drawing). This illustrates that the first and second recesses
54, 56, as well as the stationary and drive members 44, 42, can be
in any configuration, as long as the first and second recesses 54,
56 are mated to the desired stationary and drive members 44,
42.
The inflow control device 30 in FIGS. 4A-B is depicted as including
the locator profile 52 in an inner wall 31 of the device 30, where
the profile 52 can engage with the locator device 46 and anchor the
rotary actuator 40 at the predetermined location. However, it is
not necessary that the profile 52 be included with the inflow
control device 30. Alternatively, or in addition to, the profile 52
can be included in an inner wall 25 of the tubing string 24 as
indicated in intervals 16, 17, 19 in FIG. 1.
Referring now to FIGS. 5A-C, a more detailed discussion of the
operation of a certain embodiment of the rotary actuator 40 is
provided. FIG. 5A is a downstream portion (i.e., closer to the
wellhead for production operations), FIG. 5B is an intermediate
portion, and FIG. 5C is an upstream portion of the rotary actuator
40. FIG. 5A depicts the controller 62 in a chamber that can also
include an optional battery 64 for powering the controller 62, the
sensors 60, and/or the motor 66, if necessary. However, power for
operating the rotary actuator 40 is preferably supplied through a
wired connection made at the coupling 102, which couples the rotary
actuator 40 to the conveyance 32. Wires may be positioned in an
internal passage 100 that extends through the rotary actuator 40 to
distribute control and power to the components of the actuator
40.
FIG. 5B depicts a motor 66 with a rotor 69 and a stator 68, where
the rotor 69 can rotate about the axis 130 in either clockwise or
counter-clockwise directions to operate the rotary actuator 40. The
stator 68 is rotationally fixed to an outer housing 41 of the
rotary actuator 40, which prevents relative rotation between the
stator 68 and outer housing 41. The outer housing 41 is also
rotationally fixed to the stationary member 44, which prevents
relative rotation between the outer housing 41 and the stationary
member 44. The stationary member 44 includes a first magnetic
device 76 that magnetically couples the stationary member 44 to a
second magnetic device 78, which is included in an inner sleeve 72.
The first and second magnetic devices 76, 78 can include one or
more magnets that provide a sufficient magnetic coupling force to
rotationally fix the stationary member 44 to the inner sleeve 72,
thereby preventing relative rotation between the stationary member
44 and the inner sleeve 72. Magnetic flux lines of the magnetic
coupling between the first and second magnetic devices 76, 78
extend through an intermediate sleeve 74, which is positioned
between the stationary member 44 and the inner sleeve 74.
The intermediate sleeve 74 is permitted to rotate relative to the
stationary member 44 without causing the inner sleeve 72 to rotate
relative to the stationary member 44. The inner sleeve 72 is
rotationally fixed (e.g., via a threaded connection) to another
inner sleeve 82, which extends through the rotary actuator 40 to a
nose 58 of the locator device 46. The inner sleeve 82 is
rotationally fixed to the nose 58 via engagement of a splined nose
84 of the inner sleeve 82 with a splined recess 86 of the nose 58.
The engagement of the splined nose 84 with the splined recess 86
allows longitudinal movement between the nose 84 and recess 86
while transferring torque between the nose 84 and recess 86. The
nose 58 is rotationally fixed to engagement members 50 which are
selectively extended and retracted to anchor and release the rotary
actuator 40 to or from the predetermined location in the tubing
string 24. Therefore, the nose 58 and engagement members 50 do not
rotate relative to the stator 68 or stationary member 44. When the
stationary member 44 is engaged with the first recess 54, then the
stator 68, the outer housing 41, the stationary member 44, the
first magnetic device 76, the second magnetic device 78, the inner
sleeve 72, the inner sleeve 82, the nose 58, and the engagement
members 50 are rotationally fixed to the tubing string 24.
The rotor 69 is rotationally fixed to a drive shaft 70, which
rotates with the rotor 69 when the rotor 69 rotates. The drive
shaft 70 is rotationally fixed to the intermediate sleeve 74 via a
fastener 113 that connects the shaft 70 to the sleeve 74. The inner
sleeve 74 is rotationally fixed to the drive member 42 and the
outer sleeve 80, where the drive member and the outer sleeve 80
rotates with the rotor 69 when the rotor 69 rotates. One end of the
sleeve 80 is a splined nose 92 which engages a splined recess 94 in
the outer sleeve 81. The splines on the nose 92 and recess 94 allow
longitudinal movement between the nose 92 and recess 94 while
transferring torque between the nose 92 and recess 94. Therefore,
the outer sleeve 80 is rotationally fixed to the outer sleeve 81 as
long as the splined nose 92 is engaged with the splined recess 94.
If longitudinal displacement of the splined nose 92 is sufficient
to disengage the splined nose 92 from the splined recess 94, then
the outer sleeve 80 would no longer be rotationally fixed with the
outer sleeve 81, thereby allowing relative rotation between these
outer sleeves 80, 81. The outer sleeve 81 is rotationally fixed to
a threaded sleeve 47 via a fastener 112. Therefore, when the rotor
69 rotates about the axis 130, then the drive shaft 70, the
intermediate sleeve 74, the drive member 42, and the outer sleeve
80 rotate with the rotor 69. When the splined nose 92 is engaged
with the splined recess 94, then the rotating outer sleeve 81 and
threaded sleeve 47 also rotate with the rotor 69. When the splined
nose 92 is disengaged from the splined recess 94, then the rotating
outer sleeve 81 and threaded sleeve 47 do not rotate with the rotor
69.
The threaded sleeve 47 is threaded onto the nose 58 via threads 90.
Initially, the threaded sleeve 47 is threaded onto the nose 58 such
that the inclined surfaces 120 on the engagement members 50 engage
with the mating inclined surface 122 on the threaded sleeve 47,
thereby forcing the engagement members 50 to be retracted radially
inward. These engagement members 50 can be retracted during run-in
and during movement of the rotary actuator between locations in the
tubing string 24. When the rotary actuator 40 is positioned at or
near the predetermined location, these engagement members 50 can be
extended to enable engagement of the members 50 with a locator
profile 52.
Referring now to FIG. 6, when the engagement members 50 of the
locator device 46 are retracted and the rotary actuator 40 is
positioned at or near the predetermined location, the motor 66 can
be energized to rotate the rotor 69 in a first direction (e.g.,
clockwise). The biasing device 110 ensures that the splined nose 92
is initially engaged with splined recess 94 during run-in.
Therefore, rotation of the rotor 69 will rotate the intermediate
sleeve 74, which will rotate the drive member 42 and the outer
sleeve 80, which will rotate the outer sleeve 81 through the
engagement of the splined nose 92 with the splined recess 94. A
bearing 114 can be positioned between the rotating outer sleeve 81
and the inner non-rotating sleeve 82 to facilitate the relative
rotation between these sleeves 81, 82. The rotation of the outer
sleeve 81 will rotate the threaded sleeve 47, thereby
longitudinally moving the threaded sleeve 47 away from the
engagement members 50 due to the rotation of the threaded sleeve 47
about the threads 90. This longitudinal movement of the threaded
sleeve 47 (see arrows 124) can disengage the inclined surfaces 120
of the engagement members 50 from the mating inclined surface 122.
This disengagement allows radial outward extension of the members
50 by the biasing devices 51 and allows the members 50 to engage a
profile 52 at the predetermined location.
FIG. 6 depicts a longitudinal movement of the threaded sleeve 47
and the outer sleeve 81 by a length L2. The length of the splines
in the splined recess 94 is given as length L1. When the length L2
exceeds the length L1, then the splined nose 92 will be disengaged
from the splined recess 94, as seen in FIG. 7. When the engagement
members 50 engage the profile 52, the rotary actuator 40 is
anchored at the predetermined location. To disengage the splined
nose 92 from the splined recess 94, a compressive force F can be
applied to the rotary actuator 40, thereby compressing the actuator
40 against the profile 52. This compression of actuator 40
compresses the biasing device 110 between two thrust bearings 106,
108 and increases the length L2 such that it exceeds the length L1
by a gap L3, thereby disengaging the splined nose 92 from the
splined recess 94. This disengagement allows the upper portions of
the rotary actuator 40 to rotate as needed for actuating an inflow
control device 30 without causing rotation of the outer sleeve 81
or threaded sleeve 47, thus preventing disengagement of the
engagement members 50 from the profile 52.
When it is desired to move the rotary actuator 40 to another inflow
control device 30 in the tubing string, disengagement of the
engagement members 50 from the locator profile 52 may be necessary.
To disengage the members 50 from the profile 52, the force F is
released which allows the biasing spring 110 to once again cause
engagement between the splined nose 92 and splined recess 94, as
seen in FIG. 6. Once the splined nose 92 is engaged with the
splined recess 94, rotation of the rotor 69 in a second direction
(e.g., counter-clockwise), which is opposite the first direction,
will cause the threaded sleeve 47 to move longitudinally (see
arrows 124 in FIG. 6) as the threaded sleeve is threaded along
threads 90. The longitudinal movement of the threaded sleeve 47
will once again engage the inclined surfaces 120 of the engagement
members 50 with the mated inclined surface 122 of the threaded
sleeve 47, thereby causing the members 50 to retract radially and
disengage from the locator profile 52.
It should be clearly understood that even though the locator device
46 may be preferred when operating the rotary actuator 40, it is
not necessary that the locator device 47 is used at all. The rotary
actuation of inflow control devices 30 by the rotary actuator 40
can still be performed without using the locator device 47 to
locate the rotary actuator at the predetermined location in the
tubing string 24. It should also be clearly understood that many
other configurations of the locator device 46 can be used instead
of the example given above. For example, extendable dogs, keys,
and/or lugs may be used to selectively engage another profile 52. A
locking mandrel type device can also be used, as well as an active
anchoring system.
The rotary actuator 40 may be moved to any inflow control device 30
in the tubing string 24 or any other tubing strings 24 that can be
installed in lateral wellbores. To enter a tubing string 24 in a
lateral wellbore, a guide nose can be installed on the nose 58 to
selectively cause the rotary actuator 40 to enter a tubing string
24 in a lateral wellbore. Many configurations of a guide nose are
available for this purpose, so the guide nose will not be discussed
further.
Referring again to FIG. 5B, when referring to the stationary member
44 or the drive member 42, it should be clearly understood that
each member 44, 42 can include multiple members 44, 42,
respectively, and that each member can engage with a selected one
of the recesses. Therefore, there can be multiple first recesses 54
to engage with multiple stationary members 44, and multiple second
recesses 56 to engage with multiple drive members 42. With the
rotary actuator 40 at the predetermined location in the tubing
string, the stationary and drive members 44, 42 will be correctly
positioned longitudinally in the tubing string 24 with the first
and second recesses 54, 56, respectively. The rotary actuator 40
may need to be rotated slightly to engage the stationary member 44
with the first recess 54, and the drive member 42 with the second
recess 56. Once engaged, the stationary member 44 is rotationally
fixed to the first recess 54, and the drive member 42 is
rotationally fixed to the second recess 56. The members 44, 42 can
be disengaged from the recesses 54, 56 by merely moving the rotary
actuator 40 longitudinally away from the recesses 54, 56. The
biasing devices 116, 118 allow the members 44, 42 to retract as
needed as the rotary actuator travels through the tubing string 24.
However, if the locator device 46 is used, then it must be
disengaged to allow the rotary actuator 40 to move further into the
tubing string 24.
If the orientation of the inflow control device 30 is also known,
then the position of the closure member 48 of the device 30 is
known when the drive member 42 engages the recess 56. However, if
the orientation of the device 30 is not known, then it can be
determined by various ways. For example, the drive member 42 can
rotate the closure member 48 to its stops in one direction, record
the orientation of the drive member 42, then rotate the closure
member 48 to its stops in an opposite direction, and record the
orientation of the drive member 42. This would provide the complete
range of the closure member 48 for the device 30 at that location
from fully closed to fully open positions. Additionally,
orientation sensors 60 can be used to determine the orientation of
the rotary actuator 40, and once the stationary and drive members
44, 42 are engaged with the respective recesses 54, 56, the
orientation of the device 30 at that location can be
determined.
The rotary actuator 40 can be used to individually adjust inflow
control devices 30 in a tubing string 24. The inflow control
devices can be adjusted to open, close, or partially open
individual inflow control devices. For example, if water is being
produced from a wellbore interval 19, then the rotary actuator 40
can be deployed to close the inflow control device 30 in the
internal 19 to prevent water production from that zone. If a higher
velocity fluid is being produced from or injected into a wellbore
interval, then the rotary actuator 40 can be deployed to further
restrict flow through the inflow control device 30 at the internal
to reduce the fluid velocity, if desired. If a higher grade oil is
being produced from wellbore interval 17 than the oil being
produced from either one of the intervals 16 or 18, then the rotary
actuator can be moved between the inflow control devices 30 in
these intervals to reduce flow restriction to flow from interval 17
while increasing a restriction to flow from the intervals 16 and
18. Additionally, if a wellbore 11 in the well system 10 is being
used for steam injection treatment of the formation 20, then the
rotary actuator 40 can be moved between the multiple inflow control
devices 30 in wellbore 11 to individually vary flow restrictions
through these devices 30 into the formation to control a steam
front as it progresses through the formation 20. The rotary
actuator 40 can be used to move between one or more of the inflow
control devices to adjust the flow rates of fluid flowing through
each of the inflow control devices. In this manner, the desired
flow rate in each zone can be more effectively managed using the
same tool to adjust the flow rates.
Therefore, the present system is well adapted to attain the ends
and advantages mentioned as well as those that are inherent
therein. The particular embodiments disclosed above are
illustrative only, as the present invention may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims below. It is, therefore, evident that the particular
illustrative embodiments disclosed above may be altered or modified
and all such variations are considered within the scope and spirit
of the present invention. As used herein, the words "comprise,"
"have," "include," and all grammatical variations thereof are each
intended to have an open, non-limiting meaning that does not
exclude additional elements or steps. While compositions and
methods are described in terms of "comprising," "containing," or
"including" various components or steps, the compositions and
methods also can "consist essentially of" or "consist of" the
various components and steps.
Whenever a numerical range with a lower limit and an upper limit is
disclosed, any number and any included range falling within the
range is specifically disclosed. In particular, every range of
values (of the form, "from about a to about b," or, equivalently,
"from approximately a to b") disclosed herein is to be understood
to set forth every number and range encompassed within the broader
range of values. Also, the terms in the claims have their plain,
ordinary meaning unless otherwise explicitly and clearly defined by
the patentee. Moreover, the indefinite articles "a" or "an," as
used in the claims, are defined herein to mean one or more than one
of the element that it introduces. If there is any conflict in the
usages of a word or term in this specification and one or more
patent(s) or other documents that may be incorporated herein by
reference, the definitions that are consistent with this
specification should be adopted.
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